chapter 01 introduction

Electric Submersible Pumps Mohamed Dewidar 2013

Chapter 1

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Selection of Artificial Lift Types

Table of Content

Section Content Page

1 Introduction 2

2 The need for artificial lift 2

3 Review of artificial lift techniques 4

4 Selection of artificial lift criteria 5

4.1 Well and reservoir criteria

4.2 Field location

4.3 Operational problems

4.4 Economics

5 Implementation of artificial lift selection

technique 8

6 Long term reservoir performance and facility

constraints 10


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Selection of Artificial Lift Types

1.1. Introduction and selection criteria

This chapter will introduce the topic of artificial lift –

a production engineering topic of increasing importance in

field development. The reasons leading to this increasing

importance in the field development process will be reviewed.

The main factors influencing the selection of the most

important artificial lift techniques will be highlighted.

A brief description will then be given of all the common

artificial lift techniques (rod pumps, electric submersible

pumps, progressive cavity pumps and hydraulic pumps)apart from

gas lift.

Hydrocarbons will normally flow to the surface under natural

flow when the discovery well is completed in a virgin

reservoir.

The fluid production resulting from reservoir development will

normally lead to a reduction in the reservoir pressure,

increase in the fraction of water being produced together with

a corresponding decrease in the produced gas fraction. All

these factors reduce, or may even stop, the flow of fluids

from the well.

The remedy is to include within the well completion some form

of artificial lift. Artificial lift adds energy to the well

fluid which, when added to the available energy provided “for

free” by the reservoir itself, allows the well to flow at a

(hopefully economic) production rate.

1.2. The need for artificial lift

Artificial lift is required when a well will no longer

flow or when the production rate is too low to be economic.

Figure (1.1) illustrates such a situation, the reservoir

pressure is so low that the static fluid level is below the

wellhead. Question: Is it possible for this well to flow

naturally under and conditions.

Answer: Yes: If the well productivity Index is sufficiently

high and the produced fluid contains enough gas that the

flowing fluid pressure gradient gives a positive wellhead

pressure. But, the well has to be "kicked off" (started

flowing) by swabbing or other techniques.


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Fig (1.1) the well is unable to initiate natural flow

Figure (1.2) shows how installation of a pump a small distance

below the static fluid level allows a limited drawdown (Dp')

to be created. The well now starts to flow at rate q.

N.B. the static and flowing pressure gradients in figures 1.1

& 1.2 are similar since frictional pressure losses in the

tubing are small at this low flow rate.

Fig (1.2)


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It can be readily seen that the same production rate will

occur when the pump is relocated to the bottom of the tubing,

provided the pressure drop across the pump, and hence the

drawdown, remains the same. The advantage of placing the pump

near the perforations is that the maximum potential production

can now be achieved {figure (1.3)} by imposing a large

drawdown (DP") on the formation and “pumping the well off” by

producing the well at q2 is slightly smaller than the AOF.

Fig (1.3)

1.3. Review of artificial lift techniques

The most popular forms of artificial lift are illustrated in

figure (1.4). They are:

(i) Rod Pumps

Downhole plunger is moved up and down by a rod connected to an

engine at the surface. The plunger movement displaces produced

fluid into the tubing via a pump consisting of suitably

arranged travelling and standing valves mounted in a pump

barrel.

(ii) Hydraulic Pumps

Use a high pressure power fluid to:

(a) Drive a downhole turbine pump or


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(b) Flow through a venturi or jet, creating a low pressure area which produces an increased drawdown and inflow from the

reservoir.

(iii) Electric Submersible Pump (ESP)

Employs a downhole centrifugal pump driven by a three

phase, electric motor supplied with electric power via a cable

run from the surface on the outside of the tubing.

(iv) Gas Lift

It involves the supply of high pressure gas to the

casing/tubing annulus and its injection into the tubing deep

in the well. The increased gas content of the produced fluid

reduces the average flowing density of the fluids in the

tubing, hence increasing the formation drawdown and the well

inflow rate.

(v) Progressing Cavity Pump (PCP)

It employs a helical, metal rotor rotating inside an

elastomeric, double helical stator. The rotating action is

supplied by downhole electric motor or by rotating rods.

Fig (1.4) the most popular types of artificial lift

1.4. Selection of artificial lift criteria


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There are many factors that influence selection of

artificial lift. Some of the factors to be considered are:

1.4.1. Well and Reservoir Characteristics

Production casing size.

Maximum size of production tubing and required (gross)

production rates.

Annular and tubing safety systems.

Producing formation depth and deviation (including doglegs, both planned and unplanned).

Nature of the produced fluids (gas fraction and

sand/wax/asphaltene production).

Well inflow characteristics. A “straight line” inflow

performance relationship associated with a dead oil is more

favorable than the curved “Vogel” relationship found when

well inflow takes place below the fluid’s bubble point.

Figure (1.5) shows that reducing the flowing bottomhole

pressure from 2500 to 500 psi increases the well production

rate by 125% for the dead oil. This is more than double the

60% increase expected for the same reduction in bottomhole

pressure if a “Vogel” type inflow relationship is followed

with a well producing below the bubble point.

Fig (1.5) Influence of fluid in flow performance on production

increase achieved when well drawdown is increased

1.4.2. Field Location

Offshore platform design dictates the maximum physical size

and weight of artificial lift equipment that can be

installed.

The on-shore environment can also strongly influence the

artificial lift selection made. For example:


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A remote location with minimal availability of support

infrastructure can lead to different artificial lift types

being selected for wells of similar design and producing

characteristics.

Climatic extremes e.g. arctic operations will also limit the

practical choices.

The distance from the wellhead to the processing facilities

will determine the minimum wellhead flowing pressure

(required for a give production rate). This may, for example,

make the choice of an ESP more attractive than Gas Lift. This

is because the extra pressure drop in the flowline, due to

the injected gas, makes Gas Lift an unsuitable option for

producing satellite hydrocarbon accumulations isolated from

the main field.

The power source (natural gas, mains electricity, diesel,

etc) available for the prime mover will impact the detailed

equipment design and may affect reliability e.g. the voltage

spikes often associated with local electrical power

generation have been frequently shown to reduce the lifetime

of the electrical motors for ESP’s.

1.4.3. Operational Problems

Some forms of artificial lift e.g. gas lift are intrinsically

more tolerant to solids production (sand and/or formation

fines) than other forms e.g. centrifugal pumps.

The formation of massive organic and inorganic deposits -

paraffins, asphaltenes, inorganic scales and hydrates - are

often preventable by treatment with suitable inhibitors.

However, additional equipment and a more complicated downhole

completion are required unless, for example, the inhibitor

can be carried in the power fluid for a hydraulic pump or can

be dispersed in the lift gas.

The choice of materials used to manufacture the equipment

installed within the well will depend on the:

Bottom Hole Temperatures.

Corrosive Conditions e.g. partial pressure of any hydrogen sulphide and carbon dioxide, composition of the formation

water etc.

Extent of Solids Production (erosion).

Producing Velocities (erosion/corrosion).

1.4.4. Economics

A lot of attention is often paid to the initial capital

investment required to install artificial lift. However, the

operating costs are normally much more important than the

capital cost when a full life cycle economic analysis is

carried out.


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Good operating cost data for the different artificial lift

methods in different locations is difficult to find.

Reliability (discussed earlier) is one key issue while the

second is energy efficiency (and hence energy costs). This

latter is more tractable since it can be calculated from

first principles. There is a wide variation - see Figure 9.

Only rod pumps, ESP’s and PCP’s show values >50% while gas

lift, particularly of the intermittent variety, is

inefficient in energy terms. Changing energy costs can alter

the ranking order of the various artificial lift methods.

Maintenance costs will vary between operating locations

depending on the state of the local, service company

infrastructure. It can be costly in remote locations.

The number of wells in the field with that particular form of

artificial lift will influence the operating costs.

Similarly, the desirability and/or need for automation (how

many operators are to be employed) and the decision as to

whether or not to install centralized facilities will also

influence the operating costs.

1.5. Implementation of Artificial lift Selection Techniques

As discussed the artificial lift design engineer is faced with

matching facility constraints, artificial lift capabilities

and the well productivity so that an efficient lift

installation results. Frequently, the type of lift has already

been determined and the engineer has the problem of applying

that system to the particular well. A more fundamental

question is how to determine the optimum type of artificial

lift to apply in a given field.

There are certain environmental and geographical

considerations that may be overriding.

For example, sucker rod pumping is by far the most widely used

artificial lift method in North America. However, sucker rod

pumping may be eliminated as a suitable form of artificial

lift if production is required from the middle of a densely

populated city or on an offshore platform with it’s limited

deck area. There are also practical limitations - deep wells

producing several thousands of barrels per day cannot be

lifted by rod pumps. Thus, geographic and environmental

considerations may make the decision. However, there are many

considerations that need to be taken into account when such

conditions are not controlling.

Some types of artificial lift are able to reduce the sand face

producing pressure to a lower value than others. The

characteristics of the reservoir fluids must also be


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considered. Wax & formation solids present greater

difficulties to some forms of artificial lift than others. The

producing gas-liquid ratio is key parameter to be considered

by the artificial lift designer. Gas represents a significant

problem to all of the pumping methods; while gas lift, on the

other hand, utilizes the energy contained in the produced gas

and supplements this with injected gas as a source of energy.

The “Advantages and Disadvantages of the Major Artificial Lift

Methods” are listed and compared below:

Advantages

Rod Pumps

Simple, basic design.

Unit easily changed.

Simple to operate.

Can achieve low BHFP.

Can lift high temperature, viscous oils.

Pump off control.

Electric Submersible Pump

Extremely high volume lift using up to1,000 kw motors.

Unobtrusive surface location.

Downhole telemetry available.

Tolerant high well elevation / doglegs Corrosion / scale treatments possible.

Venturi Hydraulic Pump

High volumes.

Can use water as power fluid.

Remote power source.

Tolerant high well deviation / doglegs.

Gas Lift

Solids tolerant.

Large volumes in high PI wells.

Simple maintenance.

Unobtrusive surface location / remote power source.

Tolerant high well deviation / doglegs.

Tolerant high GOR reservoir fluids.

Wirleine maintenance.

Progressing Cavity Pump

Solids and viscous crude tolerant.

Energy efficient.

Unobtrusive surface location with downhole motor.


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Disadvantages

Rod Pumps

Friction in crooked / holes.

Pump wear with solids production (sand, wax etc(.

Free gas reduces pump efficiency Obtrusive in urban areas.

Downhole corrosion inhibition difficult.

Heavy equipment for offshore use.

Electric Submersible Pump

Not suitable for shallow low volume wells.

Full workover required to change pump.

Cable susceptible to damage during installation with tubing.

Cable deteriorates at high temperatures.

Gas and solids intolerant.

Increased production casing size often required.

Venturi Hydraulic Pump

High surface pressures.

Sensitive to change in surface flowline pressure.

Free gas reduces pump efficiency.

Power oil systems hazardous.

High minimum FBHP.

Abandonment pressure may not be reached.

Gas Lift

Lift gas may not be available.

Not suitable for viscous crude oil or emulsions.

Susceptible to gas freezing / hydrates at low temperatures.

High minimum FBHP.

Abandonment pressure may not be reached.

Casing must withstand lift gas pressure.

Progressing Cavity Pump

Elastomars swell in some crude oils.

Pump off control difficult.

Problems with rotating rods (windup and after spin) increase with depth.

1.6. Long Term Reservoir Performance and Facility

Constraints

Another factor that needs to be considered is long term

reservoir performance. Some years ago Neely indicated that two

approaches, both of which have disadvantages, are frequently


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used to solve the problem of artificial lift selection and

sizing.

A prediction of long term reservoir performance is made and artificial lift equipment installed that can handle the

well’s production and producing conditions over its entire

life. This frequently leads to the installation of oversized

equipment in the anticipation of ultimately producing large

quantities of water.

As a result, the equipment may have operated at poor

efficiency due to underloading over a significant portion of

its total life.

The other extreme is to design for what the well is producing today and not worry about tomorrow. This can lead to many

changes in the type of lift equipment installed during the

well’s producing life. Low cost operations may result in the

short term, but large sums of money will have to be spent

later on to change the artificial lift equipment and/or the

completion.

Likewise, in a new field development, the fluid handling

requirement from some artificial lift types can significantly

increase the size and cost of the facilities required.

Only the produced fluid is handled through the facilities with

rod pumps and ESPs.

However, gas lift requires injection gas compression and

distribution facilities and the additional, produced gas

increases the size of the production facilities required.

Similarly, the use of Hydraulic pumps can result in the

additional power fluid volumes being many times that of the

produced oil volume. These results in high fluid handling

costs as well as difficulties in accounting for the oil

produced (when oil is used as a power fluid).

The selection of the artificial lift for a particular well

must meet the physical constraints of the well. Once a

particular type of lift is selected for use, consideration

should be given to the size of the well bore required to

obtain the desired production rate. It can happen that the

desired production cannot be obtained because the casing

program was designed to minimize well cost, resulting in a

size limitation on the artificial lift equipment that can be

installed. Even if production rates can be achieved, smaller

casing sizes can lead to higher, long term production costs

due to well servicing problems, gas separation problems etc.

Figure (1.6) is offered as a screening selection tool in which

areas where particular artificial lift methods have been

frequently applied are compared as a function of depth and

well rate. It must be realized that there are many proven


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applications where a particular form of artificial lift has

been installed in a well at greater depths or produced at

higher rates than is indicated in this figure.

Fig (1.6) typical application areas of artificial lift techniques